Rigid subsea pipelines are commonly formed of lengths of steel pipe—‘pipe joints’—that are welded together end-to-end. Pipe joints are typically about 12 m in length but may be manufactured in multiples of that length, such as double, triple or quad pipe joints. To mitigate corrosion of the pipeline and to insulate the fluids that the pipeline carries in use, pipe joints are pre-coated, when manufactured, with protective and thermally-insulating parent coatings.
It is important to understand that in the subsea oil and gas industry, the terms ‘rigid’ and ‘flexible’ as applied to pipes have clear meanings that differ in important respects from general language. For example, nominally ‘rigid’ pipes have enough flexibility to be bent if a minimum bend radius is observed. Yet, such pipes are not regarded in the industry as being ‘flexible’.
Flexible pipes used in the subsea oil and gas industry are specified in API (American Petroleum Institute) Specification 17J and API Recommended Practice 17B. The pipe body is composed of a composite structure of layered materials, in which each layer has its own function. Typically, polymer tubes and wraps ensure fluid-tightness and thermal insulation. Conversely, steel layers or elements provide mechanical strength; for example, interlocked steel tapes form a carcass or pressure vault and a tensile armour is formed of helically-wound wire. Flexible pipes are terminated and assembled by end fittings. Unlike rigid pipelines that are fabricated by welding together multiple pipe joints, flexible pipelines are typically manufactured continuously to the desired length between their end fittings.
The structure of a flexible pipe allows a large bending deflection without a similarly large increase in bending stresses. The bending limit of the composite structure is determined by the elastic limit of the outermost plastics layer of the structure, typically the outer sheath, which limit is typically 6% to 7% bending strain. Exceeding that limit causes irreversible damage to the structure. Consequently, the minimum bending radius or MBR of flexible pipe used in the subsea oil and gas industry is typically between 3 and 6 meters.
Conversely, rigid pipes used in the subsea oil and gas industry are specified in API Specification 5L and Recommended Practice 1111. In contrast to flexible pipes, a rigid pipe usually consists of or comprises at least one pipe of solid steel or steel alloy. However, additional elements can be added, such as an internal liner layer or an outer coating layer. Such additional elements can comprise polymer, metal or composite materials. Rigid pipe joints are typically terminated by a bevel or a thread, and are assembled end-to-end by welding or screwing them together.
The allowable in-service deflection of rigid steel pipe is determined by the elastic limit of steel, which is around 1% bending strain. Exceeding this limit caused plastic deformation of the steel. It follows that the MBR of rigid pipe used in the subsea oil and gas industry is typically around 100 to 300 meters depending upon the cross-sectional dimensions of the pipe. However, slight plastic deformation can be recovered or rectified by mechanical means, such as straightening. Thus, during reel-lay installation of a rigid pipeline made up of welded rigid pipes, the rigid pipeline can be spooled on a reel with a typical radius of between 8 and 10 meters. This implies a bending strain above 2% for conventional diameters of rigid pipes, requiring the pipeline to be straightened mechanically upon unspooling.
Thermal insulation is an important requirement for many subsea pipelines, especially those used to transport crude oil from subsea wellheads. As collected at the outlet of a wellhead, crude oil is a viscous, multiphasic, pressurised fluid at an elevated temperature, typically around 200° C. If the crude oil is allowed to cool to a significantly lower temperature, typically below 30° C., some components of the crude oil may solidify by mechanisms such as coalescence, precipitation or gelling. The waxes, asphaltenes, hydrates or other solid condensates that appear as a result may clog the pipeline and are difficult to remove.
Polypropylene (PP) is most commonly used as the parent coating of pipe joints from which pipelines are fabricated. For example, a three-layer PP (3LPP) coating comprises a first layer of epoxy primer, a second thin layer of PP bonded with the primer and a third, thicker layer of extruded PP applied over the second layer. A five-layer PP (5LPP) coating adds two further layers, namely a fourth layer of PP modified for thermal insulation, such as glass syntactic PP (GSPP) or a foam, surrounded by a fifth layer of extruded PP for mechanical protection of the insulating fourth layer. Similar additional layers are possible for further thermal insulation, as in a seven-layer PP (7LPP) coating.
A short length of pipe is left uncoated at each end of a pipe joint to facilitate welding to abutting pipe joints. After welding, the resulting field joint comprises two bare steel pipe ends of the abutting pipe joints and the butt weld that joins those pipe joints together. Consequently, the field joint defines a gap in the parent coating that was applied to the pipe joints when they were manufactured.
Once the weld between abutting pipe joints passes testing, the field joint must be coated with a field joint coating to mitigate corrosion and to maintain the necessary degree of insulation. Thus, the field joint coating fills the gap in the parent coating. In this respect, it is important that pipelines are covered by continuous thermal insulation extending across the field joints between the successive pipe joints. Otherwise, cold spots may arise that could promote clogging of the pipeline by solid condensates.
A design constraint particularly of reel-lay pipelines is that the outer diameter of the field joint coating cannot be significantly different to the outer diameter of the parent coatings on the adjacent pipe joints.
Field joint coatings may be applied by casting or injection-moulding techniques using thermoset materials such as polyurethane (PU) that cure and harden by cross-linking or thermoplastic materials such as PP that cure and harden by cooling.
In a cast-moulded PU (CMPU) process, an example of which is disclosed in DE 102007018519, the exposed pipe surface at the abutting welded ends of the pipe joints is cleaned and a primer is applied. A mould is then positioned to enclose the field joint and a two-component urethane material is cast into the annular cavity defined within the mould around the field joint. The urethane then cures, cross-linking and solidifying to form PU in an irreversible chemical reaction. When the PU has cured sufficiently, the mould is removed to leave the field joint coating in place around the field joint.
Another approach is to use PP as the field joint coating in an injection moulded polypropylene (IMPP) process. An example of an IMPP process is disclosed in our earlier patent application published as WO 2012/004665, of which the description of the invention from page 7 at line 20 through page 25 at line 25 (paragraphs [0037] through [0138] of U.S. Published Application No. 2013-0170913 A1) and FIGS. 2 through 13 are incorporated herein by reference.
In an IMPP process, the exposed pipe surface at the abutting welded ends of the pipe joints is cleaned, primed and heated, for example using induction heating or gas flames. Exposed chamfers at the adjacent ends of the parent coatings are also heated. The field joint is then enclosed by a mould that defines an annular cavity around the field joint. Molten PP is injected into the cavity under high pressure. Once the PP has cooled sufficiently, the mould is removed, leaving a tube of PP around the field joint as the field joint coating. This tube is continuous with the tubular parent coating surrounding the pipe joints, such that the same or compatible coating materials extend all along the length of the pipe string.
A field joint coating of IMPP has broadly similar mechanical and thermal properties to a parent coating of PP. Also, the parent coating and the field joint coating are sufficiently compatible that they fuse together at their mutual interface, resisting cracking and hence giving longer service life. The service temperature of PP is also markedly higher than PU.
In many cases, pipe joints are welded together offshore aboard an installation vessel as the pipeline is laid, typically by S-lay or J-lay methods. It is also common to fabricate pipe stalks from pipe joints onshore at a spoolbase or yard and then to weld together the pipe stalks end-to-end to spool the prefabricated pipeline onto a reel. The spooled pipeline is then transported offshore for laying in a reel-lay operation. When spooling, bending of the pipeline extends beyond elastic limits into plastic deformation that must be recovered by subsequent straightening processes during unspooling when laying.
In the S-lay method, a pipeline is welded from pipe joints along a horizontal firing line. The pipeline is launched from the vessel over a stinger that supports an overbend of the pipeline, from which the pipeline curves down through the water to a sag bend leading to a touchdown point on the seabed. Field joint coating is carried out upstream of the stinger, at one or more coating stations to which the pipeline is advanced in stepwise fashion after welding.
Field joint coating is also employed during J-lay installation, in which pipe joints are lifted into a near-vertical orientation in a tower for welding to the end of the pipeline. The pipeline hangs near-vertically from the vessel and extends downwardly to a sag bend leading to a touchdown point on the seabed. Field joint coating is carried out downstream of the welding station in the tower, just before launching a newly-added pipe joint into the sea.
In principle, S-lay allows faster pipelaying than J-lay but J-lay is necessary in challenging situations where water depth and strong currents make S-lay impractical without imparting large strains to the pipeline. However, where the pipeline diameter allows, a variant of S-lay called Steep S-lay may be employed in deep water. In Steep S-lay, the pipeline undergoes a deflection through approximately 90° in the overbend from the horizontal firing line to a near-vertical departure angle as it leaves the stinger before extending downwardly to the sag bend that leads to the seabed touchdown point.
The speed of spooling and pipelaying depends upon minimising the timescale of all operations on the critical path. Given the stepwise, sequential processing steps of welding and field joint coating in S-lay and J-lay methods, it is particularly important that neither welding nor field joint coating take longer than is necessary or that one process takes substantially longer than the other. Otherwise there will be a ‘bottleneck’ in the pipeline installation process.
Similarly, when fabricating pipelines for reel-lay, field joints formed between the successive pipe joints and pipe stalks must be coated before spooling. Thus, welding and field joint coating operations also lie on the critical path for fabricating pipe stalks and for spooling. In this respect, spooling can only take place after a pipe stalk has been welded correctly onto the end of the already-spooled length of pipeline and the resulting field joint has been coated. It follows that delays in welding and field joint coating operations may also affect reel-lay operations, specifically the time that is required to load a pipeline onto a reel-lay installation vessel when that vessel visits a spoolbase.
In any technique for laying rigid pipe, it will be clear that delays in fabricating the pipeline and applying field joint coatings will tie up a valuable capital asset in the form of an installation vessel that may be worth hundreds of millions of US dollars. Delays also increase operational costs of the vessel that may accumulate at a rate of hundreds of thousands of US dollars per day. Delays also risk missing a weather window during which the pipeline can be laid in a satisfactory sea state, which could delay the entire subsea installation project at even greater expense.
As delays may arise while waiting for chemical curing of a thermoset field joint coating or cooling to solidify a thermoplastic field joint coating, various prior art proposals present solutions to quicken this curing step. For example, one of the measures proposed in the aforementioned WO 2012/004665 is to place an insert into the gap between the parent coatings of abutting pipe joints before injecting molten thermoplastics material into a mould placed around that gap, hence to embed the insert. The insert is a pre-fabricated shell or assembly of thermally insulating material, which may be applied to the pipeline offline as soon as the butt weld of that field joint has been tested. The insert reduces the volume of molten thermoplastics material to inject, mould or cast and hence to cool down, thus reducing injection and cool-down time. This provides a substantial gain in terms of cycle time. It also improves mechanical properties because internal stresses and strains related to material shrinkage following injection or casting can be reduced significantly.
It will be apparent that whether S-lay, J-lay or reel-lay methods are employed to lay rigid pipe, the pipeline—including each of its successive field joint coatings—will experience substantial stresses and strains. Stresses and strains are experienced after a pipeline is laid, for example due to thermal cycling in use. However, stresses and strains are particularly prevalent before and during laying as the pipeline is deflected onto a reel, over an overbend or through a sag bend, as the case may be, during spooling or laying. The stresses and strains are most severe when spooling a coated pipeline onto a reel, which as mentioned above involves plastic deformation of the steel of the rigid pipe. The reel acting as a bending mandrel also imparts concentrated deformation forces directly to the coating that act through the coating on the underlying steel pipe.
When a pipeline undergoes substantial bending, cracks will tend to appear and de-bonding will tend to occur at the interfaces between field joint coatings and parent coatings. The presence of an insert adds further interfaces and gives rise to additional stress and strain concentrations within the field joint coating, which increases the risk of cracks appearing. Any such cracks may allow water to reach the outer surface of the steel pipe, thus corroding the pipe. Water ingress may also reduce the adhesion of the coatings to the pipe and may additionally degrade the coatings themselves. An example of such degradation is hydrolysis of a PU field joint coating under heat emanating from within the pipeline in use, which is particularly significant under the high-pressure conditions of deep water. Degradation or loss of adhesion of the coatings will tend to permit further corrosion of the pipe and to lead to a failure of thermal insulation.
When applying field joint coatings to a reeled pipeline, the approach taken in the prior art to solve the problem of cracking has been to stiffen the field joint coating system. For example in WO 2012/072894, an external stiffener sleeve is used to form a sandwich field joint coating. In WO 2010/049667, a stiffer reinforced part of the field joint coating is moulded as a preliminarily step. Disadvantageously, both of those solutions increase the time required to produce the field joint coating.
Other insert designs known in the prior art are solid, thick elastomeric rings such are disclosed in U.S. Pat. No. 4,660,861 and WO 03/095887. Such inserts are bulky items with volume boundaries just smaller than the gap to be filled. Whilst they provide effective thermal insulation and do not extend the cycle time unduly, their stiffness leads to high stresses in the field joint coating that may initiate cracks and lead to failure of the coating. More generally, their stiffness unhelpfully modifies the local bending behaviour of the pipeline, which gives rise to stress concentrations upon bending because the stiffness of the pipeline and particularly of its coatings is not consistent along its length.
Against this background, the present invention seeks to improve resistance to cracking in and around a field joint coating and also to reduce the time required to produce the field joint coating. Counter-intuitively, the invention does so by taking the opposite approach to stiffening the field joint coating system as taught by the prior art. In contrast, the invention provides a solid insert that it is sufficiently pliant to cope with local differential stress and strain concentration between all parts of the field joint coating system during bending of the pipeline.